Well sensing and control system and method

ABSTRACT

A system and method are provided for measuring, at a fluid flow rate gauge, a fluid flow rate returning from a well, for providing, by the fluid flow rate gauge, a fluid flow rate output, for measuring, by a sand flow rate gauge, a sand flow rate of sand entrained in the fluid providing, by the sand flow rate gauge, a sand flow rate output, for receiving, at input circuits of a control system, the fluid flow rate output and the sand flow rate output, for providing, at a display controller of the control system, a display output; receiving, at a display panel, the display output, and for displaying, at the display panel, the fluid flow rate and the sand flow rate, in accordance with at least one embodiment. Embodiments can also include selecting between a first and second plug catcher or a first and second choke.

CLAIM OF PRIORITY

This application claims the benefit of and priority to Provisional Application No. 62/432418, filed Dec. 9, 2016, which is incorporated herein by reference.

BACKGROUND Field of the Disclosure

The present application relates generally to wells and more specifically to monitoring and controlling operations performed on wells.

Background of the Disclosure

In the processes of drilling wells and performing completion activities to prepare the wells for production, incomplete information about process variables has limited the ability to improve the processes both while the processes are occurring and between the previous application of the processes to one well and the subsequent application of the processes to another well. Moreover, lack of adequate and timely information has also impaired reduction of risks to personnel and equipment.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure may be better understood, and its numerous features and advantages made apparent to those skilled in the art by referencing the accompanying drawings.

FIG. 1 is a block diagram of an apparatus in accordance with at least one embodiment.

FIG. 2 is a flow diagram of a method in accordance with at least embodiment.

FIG. 3 is a flow diagram of a method in accordance with at least one embodiment.

FIG. 4 is a block diagram of a control system in accordance with at least one embodiment.

The use of the same reference symbols in different drawings indicates similar or identical items.

DETAILED DESCRIPTION OF THE DRAWINGS

A method and apparatus are provided for monitoring conditions during well operations, distributing information about the conditions, and controlling the well operations based on the information about the conditions. The information can also be used to determine aspects of well operations to be performed on another well, which may be a nearby well or another well having characteristics deemed to be similar in some respect to characteristics of the previously monitored well based on the information about the conditions of the previously monitored well. There may be overlap in time between the previously monitored well and the other well, or the activities at the other well may be performed after a phase of similar activities has been completed at the previously monitored well.

The processes preceding the establishment of a productive well involve many operations. A hole is drilled into the earth, either on land or under the sea. The hole may be directed vertically (e.g., radial to the earth) or may be directed in another direction, and the direction may change during the course of drilling. For example, a hole may be drilled vertically to a desired depth, and then the hole may be drilled horizontally at a true vertical depth (TVD) for some distance at the desired depth. Casing is placed in the well to isolate the wellbore from the surrounding geological formation. The casing is cemented in place. The cement seals and stabilizes the casing.

A fracturing plug is placed in the casing past a point at which perforating and fracturing is to be performed. The fracturing plug plugs the casing, sealing the wellbore so that hydraulic fracturing occurs within a desired portion of the formation surrounding the well. A perforating gun is used to place perforating charges in the casing at a location where communication between the wellbore and the formation is desired. The perforating charges perforate the casing. A hydraulic fracturing fluid is pumped into the well under high pressure to exit the perforations and to fracture the formation, increasing the porosity of the formation to stimulate production. The fracturing fluid includes a proppant, such as sand, to prop open newly formed fractures in the formation, keeping the fractures from closing after the hydraulic fracturing. After fracturing, another fracturing plug can he placed at a shorter distance from the surface into the wellbore, the casing can be again perforated, and the formation can be fractured in the vicinity of the new perforations. The plugging, perforating, and fracturing can he repeated at shorter and shorter distances from the surface until the desired locations of perforations surrounded by fractured formation are obtained. Then, the fracturing plugs can be drilled out to open the wellbore. A drilling fluid may be pumped to the drill bit for the drilling operation. The drilling fluid returns up the wellbore, carrying with it cuttings from the drilling operation. In the case of drilling the fracturing plug, pieces of the fracturing plug can be carried with the returning fluid. A plug catcher may he used inline with the return line carrying the fluid to catch the pieces of the plug recovered from the well.

Drilling out the fracturing plugs establishes a path for fluid in the formation to flow from the formation, through the perforations, and through the casing to the well head at the surface. As fracturing fluid was pumped into the formation, fracturing fluid in the formation, less any proppant retained in the formation, can flow hack into the wellbore. The flow of the fracturing fluid into the wellbore can help remove any remaining drilling fluid from the wellbore. As the fracturing fluid flows back into the wellbore, it is recovered from the formation. Eventually, formation fluid originally present in the formation flows out of the formation into the wellbore. Testing operations are performed to assess the characteristics of the well, and the creation of the well is completed, allowing production from the well to begin.

As many variables affect the progress of the various operations, the efficacy of the operations is difficult to optimize without information about at least some of the variables. Conversely, by obtaining such information, the information can he displayed to provide awareness of operational parameter values, and aspects of the operations can be controlled in a manner responsive to the information to optimize the efficacy of the operations and to help protect health, safety, and environmental (HSE) concerns.

As one example, while it is desirable to recover fracturing fluid from a formation being fractured, the proppant included with the injected fracturing fluid is ideally left behind in the fractures to prop the fractures open. Accordingly, it is desirable that the returning fracturing fluid recovered from the well have as little proppant as possible in it. However, in the past, returning fracturing fluid has typically been stored in a tank without any real-time measurement of the quantity of sand relative to the quantity of fracturing fluid. By measuring a volumetric flow rate quantity, for example, barrels per minute, of fluid flow and a mass flow rate quantity, for example, kilograms per minute of sand flow in the returning fluid, the quantity of sand relative to the quantity of fluid can be determined. That value can be displayed and can be used to control parameters of the hydraulic fracturing operations to improve the amount of proppant retained in the formation. As one example, the composition of the fracturing fluid can be adjusted based on the real-time measurements. As another example, the volume and pressure of the fracturing fluid can be adjusted based on the real-time measurements. By measuring pressures, such as a well head pressure, a plug catcher inlet pressure, and a choke manifold pressure at a choke manifold inlet, relationships between the pressures can be determined and used to control operations of system components. As an example, measurement of the well head pressure can be used to control the composition of the fracturing fluid.

As another example, measurement of the well head pressure can be used to control the volume and pressure of the fracturing fluid. As another example, measurement of the plug catcher inlet pressure can be used to select a plug catcher within the dual plug catcher, allowing removal of accumulated plug debris from the other plug catcher within the dual plug catcher. Such selection can be performed automatically. As another example, measurement of the choke manifold pressure can be used to select a choke within the choke manifold, allowing removal of accumulated debris from the other choke of the choke manifold. Such selection can be performed automatically. The measured pressures can be displayed to provide awareness of the measured pressures.

By providing a closed-loop monitoring and control system, one or more attributes, such as process efficiency and well productivity can be improved, and management of health, safety, and environmental (HSE) aspects can be improved. For example, real-time monitoring of sand returning from a well can allow control over the proportions of the constituent components of a fluid, such as a fracturing fluid, to enhance sand retention in the geological formation being fractured. Increased sand retention can enable a well to be more productive. By displaying parameter values on a large, easily visible numeric display panel, which can be seen at significant distances from the well, any health hazards or safety hazards that may he present at the well can be avoided, as workers need not be in close proximity to the well to see the information being displayed. The display panel can also help personnel avoid any health hazards or safety hazards that may he present near other parts of the system, for example, near a gas buster tank. Improvements can be realized with respect to a single well, for example, by automatically changing between plug catchers or between chokes when the control system determines, based on sensor data, that such changes should be performed. Improvements can be realized with respect to multiple wells, for example, by using historical data from a previous well or wells to inform the control system of the optimal time to change between plug catchers or between choke based on the current data from the current well.

FIG. 1 is a block diagram of an apparatus in accordance with at least one embodiment. The apparatus 100 comprises control system 101, display panel 102, wireless transceiver 103, wireless terminal 104, electric generator 105, well head assembly 106, sand monitor 107, flow meter 108, remote-controlled dual plug catcher 109, remote-controlled dual choke manifold 110, dual-barrel gas buster tank 111, and hydraulic fracturing proppant tank 112, which may be referred to as a frac tank.

Generator 105 provides power to components, such as to control system 101 via power connection 172. Control system 101 obtains information from sensors, provides information to display panel 102 via connection 174, forwards information to wireless transceiver 103 via connection 173, and sends signals to control devices. Wireless transceiver 103 is connected to wireless terminal 104 via wireless connection 197. The sensors include, for example, well head pressure gauge 127, sand monitor 107, flow meter 108, dual plug catcher inlet pressure gauge 138, choke manifold inlet pressure gauge 152, back up flow rate monitor 165, and lower explosive limit (LEL)/hydrogen sulfide (H2S) monitor 166. Controlled devices include, for example, first plug catcher inlet valve 139, second plug catcher inlet valve 140, first plug catcher outlet valve 147, second plug catcher outlet valve 148, first choke inlet valve 153, second choke inlet valve 154, choke bypass valve 161, first choke actuator 155, second choke actuator 156, first choke outlet valve 159, and second choke outlet valve 160. Control system 101 can also control signaling devices, such as strobe and siren signaling devices 118,119, 167, and 168. Strobe and siren signaling device 118 provides a visual and audible warning with respect to remote-controlled dual plug catcher 109. Strobe and siren signaling device 119 provides a visual and audible warning with respect to remote-controlled dual choke manifold 110. Strobe and siren signaling device 167 provides a visual and audible warning with respect to hack up flow rate monitor 165. Strobe and siren signaling device 168 provides a visual and audible warning with respect to LEL/H2S monitor 166.

Well head pressure gauge 127 is connected to control system 101 via connection 196. Sand monitor 107 is connected to control system 101 via connection 190. Flow meter 108 is connected to control system 101 via connection 191. Dual plug catcher inlet pressure gauge 138 is connected to control system 101 via connection 195. Choke manifold inlet pressure gauge 152 is connected to control system 101 via connection 187. Back up flow rate monitor 165 is connected to control system 101 via connection 177. Lower explosive limit (LEL)/hydrogen sulfide (H2S) monitor 166 is connected to control system 101 via connection 176.

Control system 101 is connected to first plug catcher inlet valve 139 via connection 192. Control system 101 is connected to second plug catcher inlet valve 140 via connection 194. Control system 101 is connected to first plug catcher outlet valve 147 via connection 188. Control system 101 is connected to second plug catcher outlet valve 1148 via connection 193. Control system 101 is connected to first choke inlet valve 153 via connection 185. Control system 101 is connected to second choke inlet valve 154 via connection 180. Control system 101 is connected to choke bypass valve 161 via connection 184. Control system 101 is connected to first choke actuator 155 via connection 186. Control system 101 is connected to second choke actuator 156 via connection 179. Control system 101 is connected to first choke outlet valve 159 via connection 182. Control system 101 is connected to second choke outlet valve 160 via connection 181.

Control system 101 is connected to strobe and siren signaling device 118 via connection 189. Control system 101 is connected to strobe and siren signaling device 1119 via connection 183. Control system 101 is connected to strobe and siren signaling device 1167 via connection 178. Control system 101 is connected to strobe and siren signaling device 168 via connection 175.

As an example, sand monitor 107 can be implemented using a non-intrusive acoustic sand monitor, such as the SAM400TC sand monitor, as may he obtained from ROXAR. As an example, flow meter 108 can he implemented using a single-channel clamp-on flow meter, such as a FLUXUS F608-F2 or F704 flow meter, from FLEXIM AMERICAS CORPORATION, as may be obtained from ADM. Such a flow meter uses clamp-on ultrasonic transducers to non-invasively obtain a volumetric flow rate of a fluid in liquid form flowing through the pipe on which the ultrasonic transducers are clamped. Examples of such clamp-on ultrasonic transducers are the FSK, FSM, FSQ, and FSS transducers also from FLEXIM AMERICAS CORPORATION.

Well casing 121 is connected to casing head 122. Annulus access valve 123 is connected to casing head 122. Casing spool 124 is connected to casing head 122. Annulus access valve 125 is connected to casing spool 124. Well head pressure gauge 127 is connected to annulus access valve 125.

A lower master valve 128 is connected to the casing spool 124. An upper master valve 129 is connected to lower master valve 128. Cross fitting 130 is connected to upper master valve 129. An inner wing valve 131, which may, for example, be a manual valve, is connected to cross fitting 130. An outer wing valve 132, which may, for example, be a remote-controlled valve, is connected to inner wing valve 131. Swab valve 133 is connected to cross fitting 130. A pipe 134 is connected to swab valve 133 to carry fluid from swab valve 133. Pipe 134 has a curve in it, after which is positioned sand monitor 107. As any sand (which is understood to include any proppant materials generally, such as quartz sand, sintered bauxite, aluminum, ceramic, and other suitable proppant materials) is directed through the curve in the pipe, its density, relative to the density of the fluid in which it is entrained, causes the sand to have increased contact with the interior pipe wall. Sand monitor 107 can acoustically measure a flow rate of the sand based on the sound of the sand contacting the interior pipe wall. From Sand monitor 107, a pipe 135 carries the fluid and entrained sand to flow meter 108. Flow meter 108 measures the flow of the fluid through the pipe. From flow meter 108, pipe 136 carries the fluid and entrained sand to remote-controlled dual plug catcher 109.

Remote-controlled dual plug catcher 109 provides dual plug catchers, which can minimize downtime. A first plug catcher can be used for a first period of time, for example, by opening first plug catcher inlet valve 139 and first plug catcher outlet valve 147 and by closing second plug catcher inlet valve 140 and second plug catcher outlet valve 148. When the first plug catcher is to be serviced, the second plug catcher can be used for a second period of time, for example, by opening second plug catcher inlet valve 140 and second plug catcher outlet valve 148 and by closing first plug catcher inlet valve 139 and first plug catcher outlet valve 147. The first period of time and the second period of time can be temporally contiguous, and the use of the first plug catcher can be immediately resumed after the second period of time, allowing uninterrupted use of remote-controlled dual plug catcher 109 throughout any servicing of either the first or second plug catcher of remote-controlled dual plug catcher 109.

Pipe 136 is connected to inlet 137 of the remote-controlled dual plug catcher 109. Dual plug catcher inlet pressure gauge 138 monitors the pressure of the fluid at inlet 137. When the first plug catcher is in use, the fluid is directed from inlet 137 through first plug catcher inlet valve 139 to an first plug catcher inlet end 141 of the first plug catcher, through a first plug catcher body 143 of the first plug catcher, through a first plug catcher outlet end 145 of the first plug catcher, and through first plug catcher outlet valve 147 of the first plug catcher, to an outlet 149 of remote-controlled dual plug catcher 109. When the second plug catcher is in use, the fluid is directed from inlet 137 through second plug catcher inlet valve 140 to an second plug catcher inlet end 142 of the second plug catcher, through a second plug catcher body 144 of the second plug catcher, through a second plug catcher outlet end 146 of the second plug catcher, and through second plug catcher outlet valve 148 of the second plug catcher, to outlet 149 of remote-controlled dual plug catcher 109.

From outlet 149 of remote-controlled dual plug catcher 109, pipe 150 carries fluid and any entrained sand to remote-controlled dual choke manifold 110. Remote-controlled dual choke manifold 110 provides chokes, which can minimize downtime. A first choke can be used for a first period of time, for example, by opening first choke inlet valve 153 and first choke outlet valve 159 and by closing second choke inlet valve 154 and second choke outlet valve 160. When the first choke is to be serviced, the second choke can be used for a second period of time, for example, by opening second choke inlet valve 140 and second choke outlet valve 148 and by closing first choke inlet valve 139 and first choke outlet valve 147. The first period of time and the second period of time can be temporally contiguous, and the use of the first choke can be immediately resumed after the second period of time, allowing uninterrupted use of remote-controlled dual choke manifold 110 throughout any servicing of either the first or second choke of remote-controlled dual choke manifold 110.

Pipe 150 is connected to choke manifold inlet 151 of the remote-controlled dual choke manifold 110. Choke manifold inlet pressure gauge 152 monitors the pressure of the fluid at choke manifold inlet 151. When the first choke is in use, the fluid is directed from choke manifold inlet 151 through first choke inlet valve 153 of a first choke assembly, through a first choke 157 of the first choke assembly, through a first choke outlet valve 159 of the first choke assembly, and through a choke manifold outlet 162 of remote-controlled dual choke manifold 110. When the second choke is in use, the fluid is directed from choke manifold inlet 151 through second choke inlet valve 154 of a second choke assembly, through a second choke 158 of the second choke assembly, through second choke outlet valve 160 of the second choke, to choke manifold outlet 162 of remote-controlled dual choke manifold 110.

Pipe 163 carries the fluid and any entrained sand from choke manifold outlet 162 of remote-controlled dual choke manifold 110 to an inlet 164 of dual-barrel gas buster tank 111. Once any entrained or dissolved gas is removed from the fluid by the dual-barrel gas buster tank 11l, the fluid is transferred from dual-barrel gas buster tank 111 via pipe 169. Pipe 169 is connected to frac tank valve 170. Frac tank valve 170 is connected to pipe 171, which is connected to a frac tank inlet of frac tank 112. Frac tank receives and stores the fluid and any entrained sand.

Display panel 2 displays information obtained from sensors monitored by control system 101. For example, display panel 102 includes numeric display 113 to display barrels per minute of fluid flow, numeric display 114 to display a sand per minute value showing a quantity of sand flow per minute, numeric display 115 to display a well head pressure, numeric display 116 to display a plug catcher inlet pressure, and numeric display 117 to display a choke manifold pressure at the choke manifold inlet 151. Information displayed on display panel 102 can also be displayed on wireless terminal 104 based on wireless communications transmitted from wireless transceiver 103.

As an example, display panel 102 may be an electromechanical display panel, such as a vane display, a flip-disc display, or a split-flap display, which can continue to display values even after a loss of power or an interruption of communications, for example, a loss of communications with control system 101. Alternatively, other display technologies can be used, for example, display technologies that require continuous application of electric signals to visibly render an image representative of the information being displayed.

Several elements are described above as being remote-controlled. Such remote control can be effected by applying one or more control signals from control system 101 to actuators that can be operated to change a configuration of the remote-controlled device. The motive force for effecting the change of configuration can he provided, for example, by an electromagnetic, electrostatic, pneumatic, hydraulic, or another electric, mechanical, or fluidic actuator.

FIG. 2 is a flow diagram of a method in accordance with at least one embodiment. Method 200 comprises processes 271, 272, and 273 performed at respective first, second, and third wells. Processes 271, 272, and 273 can be performed concurrently, partially concurrently, or sequentially. Process 271 begins at block 201 by emplacing a hydraulic fracturing plug. From block 201, method 200 continues to block 202, where hydraulic fracturing is performed. From block 202, method 200 continues to block 203, where the hydraulic fracturing plug is drilled out and measurements of flow rate, flow density, and pressures are made in real time. Such real time measurements can be contrasted with non-real-time measurements of an accumulated amount of material made after such material has already accumulated over time. From block 203, method 200 continues to block 204. At block 204, flow density and flow rate are integrated to quantify an amount of sand and an amount of fluid recovered. From block 204, method 200 continues to block 205. At block 205, the quantified amounts are recorded. From block 205, method 200 continues to block 206. Hydraulic fracturing can be performed at multiple locations within a well using multiple hydraulic fracturing plugs. At block 206, blocks 201 through 205 are repeated for subsequent hydraulic fracturing plugs. From block 206, method 200 continues to block 207. At block 207, the quantified amounts are combined and recorded for the well as a whole.

Process 272 begins at block 221 by emplacing a hydraulic fracturing plug. From block 221, method 200 continues to block 222, where hydraulic fracturing is performed. From block 222, method 200 continues to block 223, where the hydraulic fracturing plug is drilled out and measurements of flow rate, flow density, and pressures are made in real time. Such real time measurements can be contrasted with non-real-time measurements of an accumulated amount of material made after such material has already accumulated over time. From block 223, method 200 continues to block 224. At block 224, flow density and flow rate are integrated to quantify an amount of sand and an amount of fluid recovered. From block 224, method 200 continues to block 225. At block 225, the quantified amounts are recorded. From block 225, method 200 continues to block 226. Hydraulic fracturing can he performed at multiple locations within a well using multiple hydraulic fracturing plugs. At block 226, blocks 221 through 225 are repeated for subsequent hydraulic fracturing plugs. From block 226, method 200 continues to block 227. At block 227, the quantified amounts are combined and recorded for the well as a whole.

Process 273 begins at block 241 by emplacing a hydraulic fracturing plug. From block 241, method 200 continues to block 242, where hydraulic fracturing is performed. From block 242, method 200 continues to block 243, where the hydraulic fracturing plug is drilled out and measurements of flow rate, flow density, and pressures are made in real time. Such real time measurements can be contrasted with non-real-time measurements of an accumulated amount of material made after such material has already accumulated over time. From block 243, method 200 continues to block 244. At block 244, flow density and flow rate are integrated to quantify an amount of sand and an amount of fluid recovered. From block 244, method 200 continues to block 245. At block 245, the quantified amounts are recorded. From block 245, method 200 continues to block 246. Hydraulic fracturing can be performed at multiple locations within a well using multiple hydraulic fracturing plugs. At block 246, blocks 241 through 245 are repeated for subsequent hydraulic fracturing plugs. From block 246, method 200 continues to block 247. At block 247, the quantified amounts are combined and recorded for the well as a whole.

After completion of at least portions of processes 271, 272, and 273, method 200 continues to block 261. As examples, method 200 can continue to block 261 following completion of any of blocks 205, 206, or 207 of process 271, any of blocks 225, 226, or 227 of process 272, and any of blocks 245, 246, or 247 of process 273. At block 261, the quantified amounts are combined and recorded over multiple wells, such as separate wells at which processes 271, 272, and 273 are performed. After completion of at least portions of processes 271, 272, and 273, method 200 continues to block 262. At block 262, a well drilling or well completion process is modified according to the real-time data obtained at any of blocks 203, 223, 243, 206, 226, or 246. After completion of at least portions of processes 271, 272, and 273, method 200 continues to block 263. At block 263, a well drilling or well completion process is modified according to recorded quantified amounts, such as recorded quantified amounts recorded at any of blocks 205, 225, 245, 207, 227, 247, or 261. The well drilling process can include sub-processes such as drilling and cementing. The well completion process can include sub-processes such as perforating, plugging, hydraulic fracturing, plug drilling, and fluid backflow.

FIG. 3 is a flow diagram of a method in accordance with at least one embodiment. Method 300 begins at block 201, where a hydraulic fracturing plug is emplaced. From block 201, method 300 continues to block 202. At block 202, hydraulic fracturing is performed. From block 202, method 300 continues to block 203. At block 203, the hydraulic fracturing plug is drilled out and measurements are made of flow rate, flow density, and pressures in real time. From block 203, method 300 continues to decision block 301. At decision block 301, a decision is made as to whether or not the measured values are within limits. If not, method 300 continues to block 302. At block 302, the drilling/completion process is adjusted based on the measured values. From block 302, method 300 returns to block 203. If, at decision block 301, the decision is made that the measured values are within prescribed limits, method 300 continues to block 204. At block 204, flow density and flow rate are integrated over lime to quantify an amount of sand recovered and an amount of fluid recovered. From block 204, method 300 continues to block 205. At block 205, the quantified amounts are recorded. From block 205, method 300 continues to decision block 303. At decision block 303, a decision is made as to whether or not the quantified amounts are within limits. If not, method 300 continues to block 304. At block 304, the drilling/completion process is adjusted based on the quantified amounts. From block 304, method 300 continues to block 206. Also, if the quantified amounts are within limits at decision block 303, method 300 continues to block 206. At block 206, blocks 201 through decision block 303, and, if appropriate, block 304, are repeated for subsequent hydraulic fracturing plugs. From block 206, method 300 continues to block 207. At block 207, the quantified amounts are combined and recorded for the well as a whole. From block 207, method 300 continues to block 305. At block 305, the drilling/completion process is adjusted based on the quantified amounts for multiple wells.

As can be seen by the similarity of certain reference numerals of FIG. 3 to the reference numerals of FIG. 2, an embodiment according to FIG. 3 can be implemented with respect to an embodiment according to FIG. 2, where the additional blocks and decision blocks of FIG. 3 can be included in one or more of processes 271, 272, and 273 of FIG. 2.

By measuring the well head pressure using well head pressure gauge 127 and measuring the pressure of the fluid at inlet 137 of remote-controlled dual plug catcher 109 using dual plug catcher inlet pressure gauge 138, a pressure difference between the well head and inlet 137 can be determined and used to assess operational characteristics of the flow of the fluid. As one example, an accumulation of or obstruction by an obstructive material within the elements between the well head and inlet 137 can affect the pressure difference observed. As another example, an accumulation of or obstruction by an obstructive material within plug catcher 143 or plug catcher 144 can affect flow leading to remote-controlled dual plug catcher 109, which can affect the pressure difference observed. Flow meter 108 can measure the flow of fluid from the well head to inlet 137, so its measurements can be compared to the observed pressure differences to validate the data and to discern phenomena that may be affecting flow. For example, a pipe leak before flow meter 108 or a diversion of fluid from a valve on the fracturing tree at the well head could increase the observed pressure difference but not show up as an increase in flow as measured by flow meter 108. As another example, a pipe leak after flow meter 108 may increase the observed pressure difference and also increase flow as measured by flow meter 108.

Remote-controlled dual plug catcher 109 can he used to obtain additional information from the sensors, for example, by actuating the remote-controlled dual plug catcher 109 to switch between plug catcher 143 and plug catcher 144. If the pressure difference increases or flow increases when switching from the use of plug catcher 143 to the use of plug catcher 144, plug catcher 143 may be presumed to need to be cleaned to remove accumulated debris from it. In such situation, control system 101 can actuate remote-controlled dual plug catcher 109 to select plug catcher 144 for use while plug catcher 143 is removed from service for cleaning.

By measuring the well head pressure using well head pressure gauge 127, measuring the pressure of the fluid at inlet 137 of remote-controlled dual plug catcher 109 using dual plug catcher inlet pressure gauge 138, and measuring the pressure of the fluid at choke manifold inlet 151 using choke manifold inlet pressure gauge 152, pressure differences between the well head and inlet 137 and between inlet 137 and choke manifold inlet 151 can be determined and used to assess operational characteristics of the flow of the fluid. As an example, an accumulation of or obstruction by an obstructive material within choke 157 or choke 158 can affect flow leading to remote-controlled dual choke manifold 110, which can affect at least one pressure difference observed. Flow meter 108 can measure the flow of fluid from the well head to choke manifold inlet 151, so its measurements can be compared to the observed pressure differences to validate the data and to discern phenomena that may be affecting flow.

Remote-controlled dual choke manifold 110 can be used to obtain additional information from the sensors, for example, by actuating the remote-controlled dual choke manifold 110 to switch between choke 157 and choke 158. If the pressure difference increases or flow increases when switching from the use of choke 157 to the use of choke 158, choke 157 may be presumed to need to be cleaned to remove accumulated debris from it. In such situation, control system 101 can actuate remote-controlled dual choke manifold 110 to select choke 158 for use while choke 157 is removed from service for cleaning.

FIG. 4 is a block diagram of a control system in accordance with at least one embodiment. Detailed control system 400 illustrates control system 101 in accordance with at least one embodiment. According to such an implementation, control system 101 comprises processor 401, voltage regulator 403, memory 404, display controller 405, input circuits 406, and output circuits 407. Processor 401 comprises at least one processor core 402. Power connection 172 is connected to an input of voltage regulator 403. Voltage regulator adjusts the voltage of the power applied at power connection 172 to provide a power output at a regulated voltage. Voltage regulator 403 is connected to processor 401 via power connection 411 to provide power at the regulated voltage to processor 401. Voltage regulator 403 can also provide power at the regulated voltage or at one or more other regulated voltages to other components of control system 101, for example, to any or all of memory 404, display controller 405, input circuits 406, output circuits 407, and other components as may be present. Such power may be provided by individual power connections between voltage regulator 403 and the components, by one or more common power buses between voltage regulator 403 and the components, or by any combination thereof.

Processor 401 is connected to a wireless transceiver 103 via connection 173. Processor 401 is connected to memory 404 via memory connection 412. Processor 401 can transfer information into memory 404, for example, to store data received from sensors, to store processing results obtained from processing the data received from the sensors, and to store state information as to the states of the outputs provided by output circuits 407 to control inputs of controlled devices. Processor 401 can transfer information from memory 404 into processor 401, for example, to retrieve the stored information previously transferred to memory 404.

Processor 401 is connected to display controller 405 via connection 413. Display controller 405 comprises circuits for driving the numeric display features of display panel 102. Display controller 405 is connected to display panel 102 via connection 174. Connections from sensors and other data input devices, such as connections 196, 195, 187, 190, 191, 176, and 177, are connected to input circuits 406. Input circuits 406 are connected to processor 401 via connection 414. Input circuits receive the input signals via such connections and provide the input data to processor 401 via connection 414. Processor 401 is connected to output circuits 407 via connection 415. Processor 401 provides output signals to output circuits 407 via connection 415. Output circuits 407 are connected to controlled devices via connections, such as connections 192, 194, 188, 193, 185, 186, 180, 179, 182, and 181. Output circuits 407 output control signals to control the controlled devices via such connections.

In accordance with at least one embodiment, a system comprises a fluid flow rate gauge for measuring a fluid flow rate of a fluid returning from a well and for providing a fluid flow rate output, a sand flow rate gauge for measuring a sand flow rate of stand entrained in the fluid and for providing a sand flow rate output, a control system coupled to the fluid flow rate gauge and to the sand flow rate gauge for receiving the fluid flow rate output and the sand flow rate output and for providing a display output, and a display panel for receiving the display output and for displaying the fluid flow rate and the sand flow rate. In accordance with at least one embodiment, the system further comprises a plug catcher assembly comprising a first plug catcher. The system further comprises a plug catcher inlet pressure gauge coupled to the plug catcher assembly for measuring a plug catcher inlet pressure at an inlet of the plug catcher assembly, the plug catcher inlet pressure gauge coupled to the control system, wherein the control system is configured to receive the plug catcher inlet pressure and wherein the display panel is configured to display the plug catcher inlet pressure. In accordance with at least one embodiment, the control system is further configured to provide a plug catcher assembly control output in response to receiving the plug catcher inlet pressure and wherein the plug catcher assembly is configured to receive the plug catcher assembly control output and to select between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output. In accordance with at least one embodiment, the system further comprises a well head pressure gauge for measuring a well head pressure and for providing a well head pressure output, wherein the control system is further configured to receive the well head pressure output, to compare the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure, and to provide the plug catcher assembly control output in response to the comparing. In accordance with at least one embodiment, the system further comprises a choke manifold comprising a first choke. The system also comprises a choke manifold inlet pressure gauge coupled to the choke manifold for measuring a choke manifold inlet pressure at an inlet of the choke manifold, the choke manifold inlet pressure gauge coupled to the control system, wherein the control system is configured to receive the choke manifold inlet pressure and wherein the display panel is configured to display the choke manifold inlet pressure. In accordance with at least one embodiment, the control system is further configured to provide a choke manifold control output in response to receiving the choke manifold inlet pressure and wherein the choke manifold is configured to receive the choke manifold control output and to select between operation a first choke of the choke manifold and a second choke of the choke manifold in response to receiving the choke manifold control output. In accordance with at least embodiment, the control system is adapted to determine a sand concentration based on the fluid flow rate output and the sand flow rate output and for controlling a fracturing blender to adjust a sand quantity relative to a fluid quantity for injection into the well.

In accordance with at least one embodiment, a method comprises measuring, at a fluid flow rate gauge, a fluid flow rate returning from a well, providing, by the fluid flow rate gauge, a fluid flow rate output, measuring, by a sand flow rate gauge, a sand flow rate of sand entrained in the fluid, providing, by the sand flow rate gauge, a sand flow rate output, receiving, at input circuits of a control system, the fluid flow rate output and the sand flow rate output, providing, at a display controller of the control system, a display output, receiving, at a display panel, the display output, and displaying, at the display panel, the fluid flow rate and the sand flow rate. In accordance with at least one embodiment, the method further comprises measuring, at a plug catcher inlet pressure gauge coupled to a plug catcher assembly, a plug catcher inlet pressure at an inlet of the plug catcher assembly, the plug catcher inlet pressure gauge coupled to the control system, receiving, at the control system, the plug catcher inlet pressure, and displaying, at the display panel, the plug catcher inlet pressure. In accordance with at least one embodiment, the method further comprises providing, at the control system, a plug catcher assembly control output in response to receiving the plug catcher inlet pressure, receiving, at the plug catcher assembly, the plug catcher assembly control output, and selecting between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output. In accordance with at least one embodiment, the method further comprises measuring, at a well head pressure gauge, a well head pressure providing, at the well head pressure gauge, a well head pressure output, receiving, at the control system, the well head pressure output, comparing, at the control system, the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure, and providing, at the control system, the plug catcher assembly control output in response to the comparing. In accordance with at least one embodiment, the method of claim 8 further comprises providing a choke manifold comprising a first choke, measuring, at a choke manifold inlet pressure gauge coupled to the choke manifold, a choke manifold inlet pressure at an inlet of the choke manifold, the choke manifold inlet pressure gauge coupled to the control system, receiving, at the control system, the choke manifold inlet pressure, and displaying, at the display panel, the choke manifold inlet pressure. In accordance with at least one embodiment, the method further comprises providing, at the control system, a choke manifold control output in response to receiving the choke manifold inlet pressure, receiving, at the choke manifold, the choke manifold control output, and selecting, at the choke manifold, between operation a first choke of the choke manifold and a second choke of the choke manifold in response to receiving the choke manifold control output. In accordance with at least one embodiment, the method further comprises determining, at the control system, a sand concentration based on the fluid flow rate output and the sand flow rate output, and controlling, at the control system, a fracturing blender to adjust a sand quantity relative to a fluid quantity for injection into the well.

In accordance with at least one embodiment, a system comprises a first means for measuring a fluid flow rate of a fluid returning from a well and for providing a fluid flow rate output, a second means for measuring a sand flow rate of stand entrained in the fluid and for providing a sand flow rate output, a third means coupled to the first means and to the second means for receiving the fluid flow rate output and the sand flow rate output and for providing a display output, and a fourth means for receiving the display output and for displaying the fluid flow rate and the sand flow rate. In accordance with at least one embodiment, the system further comprises a fifth means comprising a first plug catcher, and a sixth means coupled to the plug catcher assembly for measuring a plug catcher inlet pressure at an inlet of the fifth means, the plug catcher inlet pressure gauge coupled to the third means, wherein the third means is configured to receive the plug catcher inlet pressure and wherein the fourth means is configured to display the plug catcher inlet pressure. In accordance with at least one embodiment, the third means is further configured to provide a plug catcher assembly control output in response to receiving the plug catcher inlet pressure and wherein the fourth means is configured to receive the plug catcher assembly control output and to select between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output. In accordance with at least one embodiment, the system further comprises a seventh means for measuring a well head pressure and for providing a well head pressure output, wherein the third means is further configured to receive the well head pressure output, to compare the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure, and to provide the plug catcher assembly control output in response to the comparing. In accordance with at least one embodiment, the system further comprises an eighth means comprising a first choke, and a ninth means coupled to the eighth means for measuring a choke manifold inlet pressure at an inlet of the choke manifold, the ninth means coupled to the third means, wherein the third means is configured to receive the choke manifold inlet pressure and wherein the fourth means is configured to display the choke manifold inlet pressure. In accordance with at least one embodiment, the third means is further configured to provide a choke manifold control output in response to receiving the choke manifold inlet pressure and wherein the eighth means is configured to receive the choke manifold control output and to select between operation a first choke of the choke manifold and a second choke in response to receiving the choke manifold control output.

The concepts of the present disclosure have been described above with reference to specific embodiments. However, one of ordinary skill in the art will appreciate that various modifications and changes can be made without departing from the scope of the present disclosure as set forth in the claims below. Accordingly, the specification and figures are to be regarded in an illustrative rather than a restrictive sense, and all such modifications are intended to be included within the scope of the present disclosure.

Benefits, other advantages, and solutions to problems have been described above with regard to specific embodiments. However, the benefits, advantages, solutions to problems, and any feature(s) that may cause any benefit, advantage, or solution to occur or become more pronounced are not to be construed as a critical, required, or essential feature of any or all the claims. 

What is claimed is:
 1. A system comprising: a fluid flow rate gauge for measuring a fluid flow rate of a fluid returning from a well and for providing a fluid flow rate output; a sand flow rate gauge for measuring a sand flow rate of stand entrained in the fluid and for providing a sand flow rate output; a control system coupled to the fluid flow rate gauge and to the sand flow rate gauge for receiving the fluid flow rate output and the sand flow rate output and for providing a display output; and a display panel for receiving the display output and for displaying the fluid flow rate and the sand flow rate.
 2. The system of claim 1 further comprising: a plug catcher assembly comprising a first plug catcher; and a plug catcher inlet pressure gauge coupled to the plug catcher assembly for measuring a plug catcher inlet pressure at an inlet of the plug catcher assembly, the plug catcher inlet pressure gauge coupled to the control system, wherein the control system is configured to receive the plug catcher inlet pressure and wherein the display panel is configured to display the plug catcher inlet pressure.
 3. The system of claim 2 wherein the control system is further configured to provide a plug catcher assembly control output in response to receiving the plug catcher inlet pressure and wherein the plug catcher assembly is configured to receive the plug catcher assembly control output and to select between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output.
 4. The system of claim 3 further comprising: a well head pressure gauge for measuring a well head pressure and for providing a well head pressure output, wherein the control system further configured to receive the well head pressure output, to compare the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure, and to provide the plug catcher assembly control output in response to the comparing.
 5. The system of claim 1 further comprising: a choke manifold comprising a first choke; and a choke manifold inlet pressure gauge coupled to the choke manifold for measuring a choke manifold inlet pressure at an inlet of the choke manifold, the choke manifold inlet pressure gauge coupled to the control system, wherein the control system is configured to receive the choke manifold inlet pressure and wherein the display panel is configured to display the choke manifold inlet pressure.
 6. The system of claim 5 wherein the control system is further configured to provide a choke manifold control output in response to receiving the choke manifold inlet pressure and wherein the choke manifold is configured to receive the choke manifold control output and to select between operation a first choke of the choke manifold and a second choke of the choke manifold in response to receiving the choke manifold control output.
 7. The system of claim 1 wherein the control system is adapted to determine a sand concentration based on the fluid flow rate output and the sand flow rate output and for controlling a fracturing blender to adjust a sand quantity relative to a fluid quantity for injection into the well.
 8. A method comprising: measuring, at a fluid flow rate gauge, a fluid flow rate returning from a well; providing, by the fluid flow rate gauge, a fluid flow rate output; measuring, by a sand flow rate gauge, a sand flow rate of sand entrained in the fluid; providing, by the sand flow rate gauge, a sand flow rate output; receiving, at input circuits of a control system, the fluid flow rate output and the sand flow rate output; providing, at a display controller of the control system, a display output; receiving, at a display panel, the display output; and displaying, at the display panel, the fluid flow rate and the sand flow rate.
 9. The method of claim 8 further comprising: measuring, at a plug catcher inlet pressure gauge coupled to a plug catcher assembly, a plug catcher inlet pressure at an inlet of the plug catcher assembly, the plug catcher inlet pressure gauge coupled to the control system; receiving, at the control system, the plug catcher inlet pressure; and displaying, at the display panel, the plug catcher inlet pressure.
 10. The method of claim 9 further comprising: providing, at the control system, a plug catcher assembly control output in response to receiving the plug catcher inlet pressure; receiving, at the plug catcher assembly, the plug catcher assembly control output; and selecting between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output.
 11. The method of claim 10 further comprising: measuring, at a well head pressure gauge, a well head pressure; providing, at the well head pressure gauge, a well head pressure output; receiving, at the control system, the well head pressure output; comparing, at the control system, the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure; and providing, at the control system, the plug catcher assembly control output in response to the comparing.
 12. The method of claim 8 further comprising: providing a choke manifold comprising a first choke; measuring, at a choke manifold inlet pressure gauge coupled to the choke manifold, a choke manifold inlet pressure at an inlet of the choke manifold, the choke manifold inlet pressure gauge coupled to the control system; receiving, at the control system, the choke manifold inlet pressure; and displaying, at the display panel, the choke manifold inlet pressure.
 13. The method of claim 12 further comprising: providing, at the control system, a choke manifold control output in response to receiving the choke manifold inlet pressure; receiving, at the choke manifold, the choke manifold control output; and selecting, at the choke manifold, between operation a first choke of the choke manifold and a second choke of the choke manifold in response to receiving the choke manifold control output.
 14. The method of claim 8 further comprising: determining, at the control system, a sand concentration based on the fluid flow rate output and the sand flow rate output; and controlling, at the control system, a fracturing blender to adjust a sand quantity relative to a fluid quantity for injection into the well.
 15. A system comprising: a first means for measuring a fluid flow rate of a fluid returning from a well and for providing a fluid flow rate output; a second means for measuring a sand flow rate of stand entrained in the fluid and for providing a sand flow rate output, a third means coupled to the first means and to the second means for receiving the fluid flow rate output and the sand flow rate output and for providing a display output; and a fourth means for receiving the display output and for displaying the fluid flow rate and the sand flow rate.
 16. The system of claim 15 further comprising: a fifth means comprising a first plug catcher; and a sixth means coupled to the plug catcher assembly for measuring a plug catcher inlet pressure at an inlet of the fifth means, the plug catcher inlet pressure gauge coupled to the third means, wherein the third means is configured to receive the plug catcher inlet pressure and wherein the fourth means is configured to display plug catcher inlet pressure.
 17. The system of claim 16 wherein the third means is further configured to provide a plug catcher assembly control output in response to receiving the plug catcher inlet pressure and wherein the fourth means is configured to receive the plug catcher assembly control output and to select between operation of the first plug catcher and a second plug catcher in response to receiving the plug catcher assembly control output.
 18. The system of claim 17 further comprising: a seventh means for measuring a well head pressure and for providing a well head pressure output, wherein the third means is further configured to receive the well head pressure output, to compare the fluid flow rate of the fluid to a difference between the well head pressure and the plug catcher inlet pressure, and to provide the plug catcher assembly control output in response to the comparing.
 19. The system of claim 15 further comprising: an eighth means comprising a first choke; and a ninth means coupled to the eighth means for measuring a choke manifold inlet pressure at an inlet of the choke manifold, the ninth means coupled to the third means, wherein the third means is configured to receive the choke manifold inlet pressure and wherein the fourth means is configured to display the choke manifold inlet pressure.
 20. The system of claim 19 wherein the third means is further configured to provide a choke manifold control output in response to receiving the choke manifold inlet pressure and wherein the eighth means is configured to receive the choke manifold control output and to select between operation a first choke of the choke manifold and a second choke in response to receiving the choke manifold control output. 